1. Field of the Invention
The present invention relates to a method of displacing fluids through a subterranean reservoir and, more particularly, to such a method for use in gas-condensate reservoirs.
2. Setting of the Invention
The recent trend in hydrocarbon discoveries in the western United States has been toward gas or gas-condensate reservoirs. In these reservoirs, the in-place fluid can be either one phase (liquid or gas) or two phase (gas and liquid) depending on both the pressure and the temperature of the reservoir. For example, a certain gas reservoir fluid at 300.degree. F. and 3700 psia can be initially a one-phase, dense fluid and will remain in as a single-phase as the pressure of the formation declines due to production. Further, the composition of the produced fluids from this reservoir will not change as the reservoir is depleted and this is true for any accumulation of this fluid composition where the reservoir temperature exceeds the cricondentherm, i.e., a maximum two-phase temperature. Although the remaining fluids left in this reservoir during production remain in a one-phase state, the fluids produced through a wellbore and passed into surface separators (through the same composition) can enter into the two-phase state as the fluid temperature declines, which accounts for the production of condensate liquid at the surface from a gas (one phase fluid) in the reservoir.
However, a reservoir containing the same fluid composition of the previous example but at a reservoir temperature of 180.degree. F. and an initial pressure at 3300 psia can also be initially in the single phase state when the reservoir temperature exceeds the critical temperature. As the reservoir fluid pressure declines because of production, the composition of the produced fluids remains constant until the dew point pressure is reached, below which liquid condenses out of the reservoir fluid which results in an equilibrium gas phase with a lower liquid content. The condensed liquid can become immobile within the formation unless its saturation in the pore spaces exceeds that required for fluid flow, as governed by the specific oil-gas relative permeabilities of the reservoir rock. In this particular example, the gas produced at the surface will have a lower liquid content and this process, which is called "retrograde condensation," will continue until a point of maximum liquid volume is reached. The term "retrograde" is used because the condensation of the liquids from a gas is usually associated with increasing, rather than decreasing, pressure. Further, a retrograde gas-condensate reservoir is synonymous with a gas condensate reservoir.
For qualitative purposes, the vaporization of the retrograde liquid aids the overall liquid recovery and can be evidenced by decreasing gas-oil ratios at the surface. The overall retrograde loss can be greater for lower reservoir temperatures, for high abandonment pressures, and for richer systems which have more available liquids. Also, the composition of the retrograde liquids is changed as pressure declines so that, for example, a 4% retrograde fluid volume at 750 psia can contain as much stable, surface condensate as a 6% retrograde fluid volume at 2250 psia.
It is particularly important to identify a gas-condensate reservoir early in the life of the field before substantial production has occurred, resulting in reduction of reservoir pressure, since an optimal depletion of a gas-condensate reservoir can be quite different from the depletion scheme for a non gas-condensate reservoir. Once the fluid in a gas-condensate reservoir has fallen below its dew point and liquid has condensed within the reservoir, it is quite difficult to thereafter recover this condensed liquid. Because the liquid content of a gas-condensate reservoir can be very economically valuable, and because through retrograde condensation a large fraction of this liquid can be left within the reservoir (at abandonment pressures), the practice of gas cycling to maintain reservoir pressure has been used in many condensate reservoirs.
In gas cycling, condensate liquids are removed from the produced wet-gas, usually in a surface gasoline plant and the residue or dry gas is returned to the reservoir through injection wells. This injected gas is used to partially maintain reservoir pressure and, therefore, is used to retard retrograde condensation. At the same time, the injected gas drives the wet-gas toward the producing wells; however, the reservoir pressure can still decline because the removed condensate liquids represent part of the wet-gas volume, unless additional drive or make up gas is added to the gas and injected into the reservoir. Gas cycling has several disadvantages, primarily the cost or lost revenues associated with reinjection, rather than sale, of the gas.
Other schemes have been proposed for the recovery of in-situ hydrocarbons, such as by miscible displacement. For instance, Great Britain Pat. No. 1,559,961 discloses a process wherein a first slug of a light hydrocarbon is injected into a reservoir, followed by the injection of a second slug of carbon dioxide, and thereafter by the injection of a drive agent. U.S. Pat. No. 3,354,953 discloses a process wherein a calculated amount of a solvent, on the order of 3-100% of the reservoir pore volume and which is miscible with reservoir hydrocarbons, is injected into the reservoir and followed by a scavenging fluid, such as natural gas. A nitrogen-driven miscible slug has been shown to achieve miscibility with reservoir oil at a temperature below the critical temperature of propane (Koch, H. A., Jr. in Slobod, R. L.: "Miscible Slug Process", AIME (1957) Vol. 10, pgs. 40-47) and at very low pressures (Carlisle, and Montes, Reeves, and Crawford: "Nitrogen-Driven LPG Achieves Miscibility at High Temperatures", Petroleum Engineering International, November 1982, pgs. 70-82). The miscible displacement of crude oil by a gas slug and a drive slug, containing a large amount of nitrogen, was reported in Yarborough and Smith: "Solvent and Driving Gas Compositions for Miscible Slug Displacement", Society of Petroleum Engineers, September 1970, pgs. 298-310. Further, the injection of an inert gas following a miscibility-generating hydrocarbon gas flood in order to continue miscible displacement is disclosed in "Flue Gas Injection Underway in West Texas Block 31 Field", Petroleum Equipment Services, 30:1, 1967, pgs. 42-50.
While the above references disclose various concepts to increase oil recovery by miscible displacement, none of the references disclose or suggest a method of retarding the in-situ condensation of the valuable condensate liquids by injecting into the reservoir a displacement fluid which forms or develops in situ miscibility with the in-place reservoir fluids and where the displacement fluid comprises a nonoxidizing gas and fluids produced from the reservoir.